During frac operations, operators want to minimize the number of trips they need to run in a well while still being able to optimize the placement of stimulation treatments and the use of rig/frac equipment. Therefore, operators prefer to use a single-trip, multistage fracing system to selectively stimulate multiple stages, intervals, or zones of a well. Typically, this type of fracing systems has a series of open hole packers along a tubing string to isolate zones in the well. Interspersed between these packers, the system has frac sleeves along the tubing string. These sleeves are initially closed, but they can be opened to stimulate the various intervals in the well.
For example, the system is run in the well, and a setting ball is deployed to shift a wellbore isolation valve to positively seal off the tubing string. Operators then sequentially set the packers. Once all the packers are set, the wellbore isolation valve acts as a positive barrier to formation pressure.
Operators rig up fracing surface equipment and apply pressure to open a pressure sleeve on the end of the tubing string so the first zone is treated. At this point, operators then treat successive zones by dropping successively increasing sized balls sizes down the tubing string. Each ball opens a corresponding sleeve so fracture treatment can be accurately applied in each zone.
As is typical, the dropped balls engage respective seat sizes in the frac sleeves and create barriers to the zones below. Applied differential tubing pressure then shifts the sleeve open so that the treatment fluid can stimulate the adjacent zone. Some ball-actuated frac sleeves can be mechanically shifted back into the closed position. This gives the ability to isolate problematic sections where water influx or other unwanted egress can take place.
Because the zones are treated in stages, the smallest ball and ball seat are used for the lowermost sleeve, and successively higher sleeves have larger seats for larger balls. However, practical limitations restrict the number of balls that can be run in a single well. Because the balls must be sized to pass through the upper seats and only locate in the desired location, the balls must have enough difference in their size to pass through the upper seats.
To overcome difficulties with using different sized balls, some operators have used selective darts that use onboard intelligence to determine when the desired seat has been reached as the dart deploys downhole. An example of this is disclosed in U.S. Pat. No. 7,387,165. In other implementations, operators have used smart sleeves to control opening of the sleeves. An example of this is disclosed in U.S. Pat. No. 6,041,857. Even though such systems may be effective, operators are continually striving for new and useful ways to selectively open sliding sleeves downhole for frac operations or the like.
The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.